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The dismantling of a coal-fired power plant along the Colorado River — on a site that once supplied electricity to 1.5 million Las Vegas-area homes — is now complete. Another, demolished recently in Queens, N.Y., stood as the last in a line of historic buildings on property used to generate

Changes to the U.S. Power Generation Fleet Are Being Driven by Environmental, Economic and Market Factors

number of coal-fired plants being retired now exceeds 180 units, with an average age of 54 years and service spans ranging from 19 to 86 years. The generating capacity of this group totals more than 27 gigawatts. Yet that number could expand to between 50 and 80 gigawatts of generating capacity by 2020, aftertheEPA’srulesgointoeffect.

Compliance Deadlines LoomUnquestionably, new and proposed regulations to reduce air emissions, cooling water use and coal combustion residues continue to drive these projections. Requirements to retrofit scrubbers and add other emission control technologies by mid-decade may also force the idling of smaller and medium-sized coal-fired plants across the eastern U.S. and Midwestern states.

Among the pending regulatory actions, two standout:EPA’sCrossStateAirPollution

POWER PLANT

DECOMMISSIONING:A Noble Past, Many Possible Futures

electricity since 1905. Today, six coal-fired units at a 60-year-old plant near Cincinnati, producing more than 860 megawatts of generating capacity, may be retired by January 2015 due in part to new U.S. Environmental ProtectionAgency(EPA)requirementsforemissionscontrols.Plansarealsounderwayfor a decommissioned power plant outside Austin, Texas, to become the centerpiece of a new landmark residential and retail district, complete with light rail and intercity rail connections to the adjacent downtown and area parks.

From coast to coast, an unprecedented transformation is happening within North America’s aging fleet of power plants — driven in large part by emerging environmental regulations, economics, and the rise of relatively low cost and abundant natural gas. Based on a recent Burns & McDonnell study of utilities, the

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Rule(CSAPR)andthenewNationalEmissionStandardforHazardousAirPollutants(NESHAP).FinalizedinJuly2011,CSAPRrequires 27 states to significantly improve air quality by reducing power plant emissions that cross state lines and contribute to ozone and fine particle pollution in other states. CSAPRandrelatedregulationsaredrivingowners of many coal-fired units to install scrubbers to minimize annual sulfur dioxide emissions and to reduce nitrogen dioxide through selective catalytic reduction or selective non-catalytic reduction.

However, on Dec. 30, 2011, the U.S. Court of Appeals for the District of Columbia, granted a last-minute request from electric power producerstodelayimplementationofCSAPR.This put the rule on hold through the spring, while the court weighs legal challenges. FinalizedinDecember2011,NESHAPisdesigned to reduce hazardous air pollutant emissions from coal- and oil-fired electric utility steam generating units under the Clean Air Act (CAA). In particular, the agency’s Mercury and Air Toxics Standards (MATS) sets equipment and work-practice standards to limit toxic air emissions of mercury, acid gases and other hazardous pollutants from existing power plants beginning in 2015. The EPAalsoreviseditsstandardsofperformancefor fossil fuel-fired power plants under CAA section 111(b). Additional regulations to watch within a three- to five-year span include: Best Available Retrofit Technology requirements under the Clean Air Visibility Rule; sulfur dioxide and nitrogen dioxide National Ambient Air Quality Standards; and consent decrees under New Source Review provisions of the CAA.

Even with more stringent air emissions requirements on the horizon, another market dynamic may play an even bigger role in power plant decommissioning: the growing supply of cleaner burning natural gas.

Thanks to new technologies — primarily horizontal drilling and hydraulic fracturing techniques — and plentiful domestic supplies, the price of natural gas has plummeted, making it competitive with coal. Shale gas production alone is expected to increase almost fourfold through 2035. Given the EPA’snewregulationsandthehighcostofretrofitting coal-fired facilities, electrical

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Decommissioning Drivers: New and Pending Regulations

The EPA’s co-proposed rules would require either: 1) listing these residuals as special wastes subject to regulation under Subtitle C of RCRA; or 2) regulating coal ash under Subtitle D of RCRA, the section for non-hazardous wastes, with additional national minimum standards for disposal. The first option would effectively phase out wet handling of coal combustion residuals, while the second option would allow for continued wet handling only after retrofitting surface impoundments with composite liner systems and implementing additional monitoring criteria.

More: http://epa.gov/wastes/nonhaz/industrial/ special/fossil/ccr-rule/index.htm

Clean Water Act, Section 316(b): Cooling Water Intake StructuresThe EPA is developing regulations under Section 316(b) of the Clean Water Act, requiring existing facilities that withdraw at least 2 million gallons per day of cooling water — including steam electric power plants — to use the best technology available in terms of the location, design, construction and capacity to minimize the adverse environmental impacts of cooling water intake structures. According to the agency, these impacts include the impingement of fish and shellfish on cooling water intake screens and the entrainment of their larvae and eggs into facilities’ cooling systems.

All facilities would be subject to impingement and entrainment standards. For impingement, the standards are a maximum annual mortality of 12 percent with a monthly maximum of 31 percent. Alternatively, facilities can achieve a through-screen velocity of less than 0.5 feet per second. In addition, all intake screens that are moved and sprayed with water for cleaning must be equipped with devices designed to minimize the exposure of fish to high intake velocities, the atmosphere, and high-pressure sprays, and gently return impinged fish to the source water. Facilities with ocean or tidal source waters must also reduce shellfish impingement to a level commensurate with a barrier net. For entrainment, facilities can reduce the intake flow to a level commensurate with a closed-cycle, recirculating cooling system or conduct studies to help permitting authorities determine site-specific entrainment mortality controls based on the cost of compliance and the benefit to natural resources. The EPA is expected to implement a final rule by July 27, 2012.

More: http://water.epa.gov/lawsregs/ lawsguidance/cwa/316b/index.cfm

Cross State Air Pollution Rule (CSAPR)Finalized in July 2011, the EPA’s CSAPR requires 27 states to significantly improve air quality by reducing power plant emissions that cross state lines and contribute to ozone and fine particle pollution in other states. The EPA also finalized supplemental rules on Dec. 15, 2011, requiring five states — Iowa, Michigan, Missouri, Oklahoma and Wisconsin — to make summertime nitrogen oxide (NOx) reductions under the CSAPR ozone season control program. However, the U.S. Court of Appeals for the District of Columbia granted a last-minute request (Dec. 30, 2011) by electric power producers to delay this requirement; as a result, CSAPR is on hold through the spring while the court weighs legal challenges.

To meet CSAPR requirements, electric generating facilities must either install controls, buy allowances, reduce operation, fuel switch or retire units.

More: http://epa.gov/airtransport

National Emission Standards for Hazardous Air Pollutants (NESHAP)Proposed by the EPA in May 2011, NESHAP rules address emissions of hazardous air pollutants (HAPs) from coal- and oil-fired electric utility steam generating units under Clean Air Act section 112(d). EPA identified source categories that must meet technology requirements to control HAP emissions and are required to develop standards for all industries that emit one or more of the HAPs in significant quantities.

The EPA also recently issued its Mercury and Air Toxics Standards (MATS) for power plants in December 2011 — designed to limit mercury, acid gases and other toxic pollution from power plants and reflecting application of maximum achievable control technology.

More: http://epa.gov/compliance/monitoring/ programs/caa/neshaps.html and http://epa. gov/airquality/powerplanttoxics/index.html

Coal Combustion ResidualsFor the first time, the EPA is proposing to regulate coal combustion residuals (coal ash) produced by electric generating utilities — wastes still considered exempt under an amendment to the Resource Conservation and Recovery Act (RCRA). After a series of comment periods in 2010 and public submittals during 2011, the EPA is expected to release its final rule in 2012.

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generating companies may opt instead to close plants and/or convert them to rely on more efficient combined cycle gas turbine technology.

ProjectionsbytheU.S.DepartmentofEnergyin its 2011 Annual Energy Outlook: “The role of natural gas grows due to low natural gas prices and relatively low capital construction costs that make it more attractive than coal. The share of generation from natural gas increases from 23 percent in 2009 to 25 percent in 2035.”

A Process of IntegrationWhether choosing to abandon, convert or replace an existing facility, energy providers face a complex set of choices in determining thebestcourseofaction.JeffPope,managerof environmental and remediation services for Burns & McDonnell, knows this first-hand: “Most of the owners in the power industry have been building all these years, or repowering and modifying their facilities. This is the first time they’re actually looking at having to take these units down.”

Many steps factor into the complete decommissioning and retirement of a coal-fired facility, from asset valuation and cost studies to deconstruction scoping, site remediation and possible redevelopment. For example, bidding and cost estimates should reflect the full scope of work required: structural demolition and scrap recovery as well as environmental cleanup costs and site restoration.

“Our integrated team at Burns & McDonnell brings that knowledge of the whole process,” Popesays,“tonegotiateafairpricewithdemolition contractors while addressing environmental remediation, pond closures and other issues after the physical plant comes down. It’s important to have an upfront understanding of all the aspects that go into this process.”

Retire or Not?Every decommissioning, conversion and redevelopment scenario should begin with a careful study of economic models, environmental issues and site options before

determining the best course of action. Burns & McDonnell analysts have conducted numerous studies on plant decommissioning over the past decade to support rate cases and testimony as well as for financial accounting, due diligence and other regulatory requirements.

“A decision on whether or not to decommission a plant calls for a detailed look at your entire portfolio, to see how retiring an asset fits with the rest of your plan and how those costs compare to other capital costs necessary to replace that power generation,” says Jeff Kopp, Burns & McDonnell manager of project development. He agrees on the importance of examining plant retirement as holistically as possible; otherwise, environmental costs, for example, may not be represented accurately.

A case in point: A recent Burns & McDonnell study identified a large amount of high-value scrap metal for one plant, overlooked in the demolition contractor’s estimate. “This dramatically changed the net demolition costs for that facility because we were able to uncover several million dollars in credit,” Kopp says.

The value of a decommissioning study is greater than ever. “Historically, this has been more of an accounting exercise,” Kopp says. “But now that we’re seeing a lot of announced retirements, utilities seem to be transitioning from that study phase to getting ready for actual decommissioning.”

To the Heart of the MatterDemolition may be the most visible symbol of plant decommissioning. Yet it, too, requires a careful approach to removing the complete structure, all equipment and machinery, and auxiliaries such as pumps, piping, boilers, ductwork, fans and more while recovering and recycling valuable scrap.

“First you need to address what decommissioningmeans,”Popesays. “Do you actually tear it down? Take more of an ‘abandon in place’ approach and keep additional units running at a given site? Or simply leave the abandoned assets in place, depending on the market for scrap metal?”

Making the (Rate) Case: Tampa ElectricWhen Tampa Electric Co. needed a new decommissioning report on its five fossil fuel-fired power stations, as part of its regular update to the Florida Public Service Commission (FPSC), the regulated utility turned to analysts at Burns & McDonnell for assistance. This study — required once every four years as part of its depreciation rates update — provides an estimate of total decommissioning obligations at the end of a plant’s useful life. Finalized in March 2011, the study was filed with the FPSC in support of proposed new depreciation rates.

As the principal subsidiary of TECO Energy Inc., Tampa Electric delivers 4,600 megawatts of generating capacity to more than 672,000 residential, commercial and industrial customers in west central Florida. Electric generating plants include Bayside combustion turbines (CTs, natural gas), Big Bend Steam Units (coal), Big Bend CT (natural gas/oil), Polk Unit 1 integrated gasification combined cycle (coal) and Polk Units 2-5 CTs (natural gas/oil).

“We provided them with a comprehensive look at decommissioning, as well as a full study that would hold up to regulatory scrutiny,” explains Jeff Kopp, a Burns & McDonnell analyst. “In turn, this allows Tampa Electric to support the costs expected to be incurred upon retiring any of these plants as part of its depreciation filing with the FPSC.”

As an example of the work performed, through extensive drawing reviews and site visits, Burns & McDonnell developed accurate estimates of scrap metal quantities expected at plant dismantling — and then adequately accounted for the expected scrap value. “Efforts like that essentially save future ratepayers money,” he adds, “because it means the utility appropriately charges customers through its annual depreciation rates to recover a more accurate estimate of future demolition costs.”

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Even with a decision to proceed on dismantling a facility, owners may need assistance with demolition contractors, from developing bid specs, hiring subcontractors and remediation services to assessing the recovery value of scrap materials.

“Often, we can help scope out the demolition work,” explains Vic Ranalletta, manager of the Burns & McDonnell Energy Group in the Chicago office. “Many owners have never done this before, so we’re able to walk them through the process, offer recommendations on what to include. We’ve also taken on the role of owner’s engineer, essentially acting as a general contractor for them.”

Environmental issues remain the biggest and most costly items to address as part of decommissioning. Asbestos abatement must occur before any demolition. Remediation alsoinvolvesleadabatementandPCBandmercury contamination removal where necessary. One area of uncertainty is coal ash pond closure — problematic because federal regulations have not been finalized. Additional tasks include air monitoring, permitting and site restoration.

Repowering and RedevelopmentFor most of the last century, coal-fired power plants have taken up prime real estate along rivers, in or near downtown areas, and featuring rail access, roadways, water, sewers and other utilities. Conversion to gas-fired generation offers one strong possibility, as a combined cycle plant requires significantly less space than coal-fired structures spread over hundreds of acres. Today’s natural gas-fired combustion turbine power plants also convert fuel energy to electricity at a more efficient conversion rate than conventional, older coal-fired or natural gas-fired steam power plants, at less than 7,000 British thermal units per kilowatt-hour instead of greater than 10,000. And they do it with lower operating and maintenance costs.

Repowering a plant with gas-fired elements can make sense because so much critical infrastructure is already in place, including transmission lines, substations and water. Three options must be considered in retrofitting a decommissioned plant with newer, more efficient technology, Kopp says: “Can you retrofit existing equipment, either by

converting the boilers to burn gas or installing a combustion turbine in combined cycle with the existing steam turbine? Can you reuse the site by using all-new equipment and take advantage of existing infrastructure? Or do you abandon the site altogether and build elsewhere?”

Alternatively, the best use of a decommissioned coal-fired plant may lie in redevelopment of the site for some other commercial or industrial application — as determined by key factors during the study phase of the project. A site’s location near an urban center, its historic architecture, existing infrastructure and access to transportation networks all shape the potential for repurposing a complex.

Sarah Torres, a Burns & McDonnell senior analyst, spends a lot of time considering these scenarios. “There are so many factors that go into deciding whether or not it makes sense to pursue redevelopment on a site.

“That’s where we come in and ask, ‘What will the market bear?’ Not only what can this site support, but does it make sense for the city to acquire it and transition the space into something that will support its long-term goals for economic development like a jobs incubator? Or is it best to partner with the current owner of the site and pursue a dual redevelopment strategy?” she continues. “These are just some of the possibilities that can be explored. Helping guide decision-making is the potential return on investment for individual scenarios: the short-term economic stimulus from construction, as well as the longer-term benefits of repurposing that site for recruiting business to the community while serving as a catalyst to further development.”

For more information, contact Jeff Kopp, 816-822-4239, or Jeff Pope, 630-724-3328,

Demolition may be the most visible symbol of plant decommissioning. Yet it, too, requires a careful approach to removing the complete structure, all equipment and machinery, and auxiliaries such as pumps, piping, boilers, ductwork, fans and more while recovering and recycling valuable scrap.